OGJ Newsletter

March 6, 2017
International news for oil and gas professionals

ExxonMobil increases 2017 capital spending by 16%

ExxonMobil Corp. has set its capital spending budget for 2017 at $22 billion, up 16% from 2016. Capital and exploration expenses through the end of the decade will average $25 billion/year.

More than one quarter of the company's planned spending this year will be made in short-cycle opportunities-those expected to generate positive cash flow in less than 3 years after initial investment-including in the Permian and Bakken.

The company says it has an inventory of more than 5,500 wells in the Permian and the Bakken with a rate of return of more than 10% at $40/bbl, with nearly one third generating higher returns. Total annual net production growth from the basins through 2025 could be as high as 750,000 boe/d at a compound annual growth rate of 20%.

The company also will advance longer-term projects in areas such as Canada, Guyana, and the UAE. Guyana startup is expected by 2020, fewer than 5 years after the initial discovery well (OGJ Online, Jan. 12, 2017).

ExxonMobil expects the startup of five major upstream projects in 2017-18, which will contribute an additional 340,000 boe/d of working-interest production capacity. Odoptu Stage 2 in Far East Russia and the Hebron project in Eastern Canada are expected to start up by yearend. Other projects planned for startup in the period are the Upper Zakum expansion in the UAE, Barzan in Qatar, and Kaombo in Angola.

The company has an upstream portfolio of nearly 100 projects that are in various stages of planning, concept selection, and construction.

ExxonMobil says the investments will support upstream volumes that are projected at 4 million-4.4 million boe/d through 2020.

Linn Energy, Berry Petroleum emerge as standalones

Linn Energy Inc., the reorganized successor to Linn Energy LLC, and its affiliated entities have emerged from Chapter 11 restructuring, with Linn and Berry Petroleum operating as standalone companies. Linn and Berry merged in 2013 (OGJ Online, Dec. 17, 2013).

Through the restructuring, Linn has reduced debt by more than $5 billion to a total of $1.012 billion and pro forma net debt of $962 million, resulting in $730 million of liquidity.

Linn will market 130,000 net acres in South Texas, 90,000 in the Permian, 20,000 in the Williston, 5,000 in Salt Creek, and 3,000 in California.

Linn's position now includes 185,000 net acres in SCOOP-STACK-Merge, including 49,000 net acres in the Merge, where Linn operates a 60-MMcfd refrigeration plant with expansion capability; and 2.6 million net acres that's 98% held by production with exposure to emerging stacked pay opportunities in the Midcontinent, Rockies, East Texas, and North Louisiana.

Linn says its position covers low-cost base production that averaged 828 MMcfed in 2016 with a 13% decline rate.

Perenco acquiring Gabon stakes from Total

Perenco, London, has agreed to acquire varying interests in oil and gas fields in Gabon from units of Total SA and to become operator of most of them.

The agreement, with total value of about $350 million, also includes 100% of the Rabi-Coucal-Cap Lopez pipeline network. It involves about 13,000 b/d of production.

As part of the deal, Perenco will acquire Total's wholly owned affiliate Total Participations Petrolieres Gabon (TPPG).

From TPPG, Perenco will acquire 34.7% interests in Grondin, Gonelle, Barbier, and Mandaros fields in the offshore Grondin area; 34.7% interests in Girelle and Pageau fields in the Offshore Torpille area and a 19.3% interest in Hylia field in that area; and a 13.8% interest in Coucal field, a 13.9% interest in Avocette field, and a 14.6% interest in Rabi field, all onshore.

The buyer will assume operatorship of those fields as well as of Atora field onshore from Total Gabon, in which Total holds a 58% interest. Perenco will acquire Total Gabon's 40% interest in Atora.

The pipeline acquisition is from Total Gabon. Perenco also will acquire an 18% nonoperated interest in onshore Igongo field from Total Gabon as well as some of that unit's shares in fields covered by the TPPG acquisition.

After the sale, Total Gabon will hold 65.3% nonoperated interests in the Grondin area fields and in Girelle and Pageau fields, a 37.5% interest in Hylia field, and a 32.9% nonoperated interest in Rabi field.

Not covered by the transaction are Total Gabon's 100% operated interests in offshore Anguille and onshore Ile Mandji fields in the Anguille area, 100% operated interests in Torpille and Torpille Nord Est fields in the Torpille offshore area and a 50% operated interest in Baudroie-Merou field in the same area, a 42.5% operated interest in the deep offshore Diaba Block; and a 100% operated interest in the Cap Lopez oil terminal.

Exploration & DevelopmentQuick Takes

Potential Cook Inlet lease sale to offer 224 blocks

The US Bureau of Ocean Energy Management is planning to offer 1.09 million acres in Cook Inlet off Alaska's south-central coast in Lease Sale 244, scheduled for June.

The sale would cover 224 blocks toward the northern part of the Cook Inlet planning area for leasing. The blocks stretch from Kalgin Island in the north to Augustine Island in the south.

A notice of availability will be published Feb. 27 in the Federal Register reading room, and on Feb. 28 in the Federal Register itself.

BOEM has notified Alaska Gov. Bill Walker (I) of the announcement, and as required by law will mail him a copy of the proposed notice of sale to arrive coincident with the Feb. 28 Federal Register notice of availability, which will initiate a governor's 60-day review and comment period.

"Following a robust environmental analysis, we are moving forward with the Lease Sale 244 process," said Walter Cruickshank, BOEM's acting director. The proposed notice of sale follows the Dec. 22, 2016, publication of an environmental impact statement relating to the proposed sale.

Lease Sale 244 would be the final one in the Department of the Interior's 2012-17 Outer Continental Shelf oil and gas leasing program. Publication of the notice does not mean the final decision has been made to hold the lease sale.

The next step in the leasing process is the publication of the final notice of sale. Per BOEM's regulations, this must be done at least 30 days prior to the date of the sale.

Cook Inlet lease sales in the recent past have been canceled by BOEM due to a lack of industry interest.

Reimaging project commences for US central gulf

TGS-NOPEC Geophysical Co. ASA and Schlumberger Ltd. are reimaging data covering 1,000 blocks in the central US Gulf of Mexico. Final results for the program are expected in early 2018, ahead of anticipated block turnover in the region. The study will reprocess 3D wide azimuth images covering 23,000 sq km previously acquired by both companies.

Areas included in the reimaging project are Mississippi Canyon, Atwater Valley, and Ewing Bank. Under the Bureau of Ocean Energy Management's 2017-22 program, the central gulf will undergo two licensing rounds every year.

The central gulf Lease Sale 247, the 12th and final gulf sale under the Obama administration's Outer Continental Shelf leasing program for 2012-17, will take place on Mar. 22. It will cover 9,118 blocks 3-230 miles offshore covering more than 48 million acres offshore Louisiana, Mississippi, and Alabama (OGJ Online, Dec. 22, 2016).

Shell, YPF to develop Vaca Muerta gas pilot project

Royal Dutch Shell PLC and Argentina's YPF SA have signed preliminary terms and conditions of an agreement to develop a shale gas pilot project in the Vaca Muerta shale of Neuquen province.

The agreement would provide each company 50% working interest with Shell as operator in the 55,000-acre Bajada de Anelo northeast of Loma Campana, a strategic region in Vaca Muerta that has both shale oil and shale gas resources, according to a release from YPF.

Shell estimates the project would require investment of $300 million, which would occur in two phases.

YPF Chairman Miguel Angel Gutierrez noted the importance of a new partner in Vaca Muerta "after the addendum to the collective bargaining agreement" that was recently sealed among stakeholders in the Neuquen basin.

The Argentine government last month struck a deal with labor unions and international oil firms-including Shell, Chevron Corp., BP PLC, and Total SA-to attract investment to Vaca Muerta.

As part of the deal, the government will provide a subsidized wellhead price of $7.50/MMbtu through 2020 and invest in infrastructure surrounding oil and gas operations. In turn, the firms pledged to invest $5 billion in 2017, with that total multiplying in subsequent years.

Shell's presence in Argentina includes its 22.5% nonoperated interest, held since 1998, in the Acambuco natural gas and condensate block in Salta province. That concession is operated by Pan American Energy LLC.

In 2012, Shell became operator with 90% interest in the unconventional Sierras Blancas, Aguila Mora, and Cruz de Lorena blocks in Neuquen. It also has 45% nonoperated interest in the province's La Escalonada and La Ceniza Corner blocks.

The US Energy Information Administration estimates Vaca Muerta holds 308 tcf of dry, wet, and associated shale gas resources.

Drilling & ProductionQuick Takes

Shell takes FID on Kaikias project in deepwater gulf

Shell Offshore Inc., a subsidiary of Royal Dutch Shell PLC, and MOEX North America LLC, a wholly owned subsidiary of Japan's Mitsui Oil Exploration Co. Ltd., have each taken the final investment decision on Phase 1 of the Kaikias deepwater project in the US Gulf of Mexico.

The project will produce oil and natural gas through a subsea tieback to the nearby Shell-operated Ursa production hub and will be developed in two phases. The first phase, expected to start production in 2019, includes three wells designed to produce as much as 40,000 boe/d at peak rates.

Kaikias is in the Mars-Ursa basin 130 miles offshore Louisiana and is estimated to hold more than 100 million boe of recoverable resources. Shell discovered Kaikias in August 2014, and appraisal drilling revealed more than 300 ft of net oil pay in August 2015.

Shell says redeveloping exploration and appraisal wells for production minimized new drilling at Kaikias, and existing oil and gas processing equipment on Ursa reduces the need for additional topside modifications, cutting overall operating costs.

Kaikias' simplified design is resulting in a 50% reduction in total costs vs. initial estimates, Shell says, adding the project has a go-forward breakeven price of less than $40/bbl.

Shell is operator of Kaikias with 80% working interest, and MOEX owns the remaining 20%. Mitsui agreed to acquire its interest in December 2016 (OGJ Online, Dec. 6, 2016).

Delek Group adopts FID for Leviathan's Stage 1A

Delek Group has adopted a final investment decision for development of Stage 1A for the Leviathan natural gas discovery offshore Israel.

Stage 1A of the development plan has a proposed budget of $3.75 billion with a capacity of 12 billion cu m/year of gas starting by yearend 2019. This annual capacity rate was incorrectly reported as a daily rate in an earlier story (OGJ Online, Dec. 12, 2016).

Dussafu deals firming before output start

BW Energy Gabon Pte. Ltd.'s plan to start oil production from the Dussafu production-sharing contract offshore Gabon next year has advanced with the firming of two deals to acquire interests totaling 91.67% (OGJ Online, Dec. 22, 2016).

The company's $32-million purchase of a 66.67% stake from a unit of Harvest Natural Resources Inc. received approval by the seller's shareholders.

And the wholly owned subsidiary of BW Energy Holdings Pte. Ltd. entered a definitive agreement to acquire a 25% working interest in the PSC from Pan-Petroleum Gabon BV, a wholly owned subsidiary of Panoro Energy ASA, London, for $12 million. The seller's interest now is 33.33%.

Harvest shareholders also approved dissolution of the company once the sale is completed and proceeds are distributed.

BW Energy Holdings is a joint venture of BW Offshore (66.67%) and Maple Co. Ltd., a wholly owned subsidiary of BW Group Ltd., Singapore.

Harvest Dussafu BV made two presalt oil discoveries on the block: Ruche in 2011 and Tortue in 2013. Both found pay in the Cretaceous Gamba and Dentale formations. Oil discoveries preceding Harvest's acquisition of the interest include Moubenga in 1981 and Walt Whitman in 1996.

The Gabonese government awarded an exclusive exploitation authorization for development of all four fields inside a 2,775-sq km license named for Ruche field, where water depth is about 120 m. PSC area outside the license has been relinquished. Production is to start by mid-2018.

The development plan is for horizontal and vertical wells completed subsea and tied back to a floating production, storage, and offloading vessel moored at Ruche field.

When BW Energy entered preliminary agreements to acquire the Dussafu interests last December, it estimated development costs beyond the interest acquisitions at $150 million.


Canada advances new clean-fuel standard

Canadian refiners face toughened regulation of their products and facilities under plans for a clean-fuel standard published for comment by the federal government.

Seeking to cut greenhouse gas emissions by 30 megatonnes/year by 2030, the standard would include "a market-based approach, such as a crediting and trading system," according to a discussion paper from Environment and Climate Change Canada (ECCC).

And it would "incent the use of a broad range of lower-carbon fuels and alternative sources and technologies, such as electricity, renewable natural gas, hydrogen, and renewable fuels."

The standard would apply to liquid, gaseous, and solid fuels used not only in transportation but also in industry, homes, and buildings.

The targeted emissions cut, part of a federal program to lower GHG emissions by 30% during 2005-30, would be imposed atop measures now in place.

The ECCC said it is considering "overall life-cycle carbon-intensity reductions" of 10-15% by 2030. The reductions would apply to a baseline that "could be a sector-wide average, facility-specific, or set on some other basis."

The federal government now imposes volumetric renewable-content requirements of 5% of gasoline and 2% of diesel and heating distillate oil sold by refiners and importers.

Next year it will require provinces to implement programs equivalent to taxing carbon dioxide at rates beginning at $10/tonne and rising to $50/tonne in 2022.

The ECCC is taking written comments on the clean-fuel standard until Apr. 25.

ORPIC: Sohar refinery expansion due for commissioning

Oman Oil Refineries & Petroleum Industries Co. (ORPIC) has completed all construction and precommissioning works for the multibillion-dollar Sohar Refinery Improvement Project (SRIP), a long-planned, brownfield modernization program to technically enhance the operator's existing 116,000-b/d refinery about 230 km northwest of Muscat.

The SRIP team achieved the major milestone on Feb. 22, reaching mechanical completion of the delayed coker, sulfur recovery units, utility and offsite units, as well as other unidentified brownfield works within the refinery, OPRIC announced via its official social media web sites.

With all mechanical construction and precommissioning works for SRIP wrapped, OPRIC is now ready to kick-start commissioning and startup activities for the modernized units, the company said.

While ORPIC previously confirmed SRIP was on schedule for planned startup sometime in late 2016-17, the operator did not reveal a revised, definitive timeline for when the expanded refinery will be fully commissioned (OGJ Online, Feb. 23, 2016).

Designed primarily to improve the Sohar refinery's ability to overcome existing technical constraints associated with processing the changing quality of Oman Export Blend (OEB) crude, SRIP also will enable the refinery to meet international environmental standards, serve growing domestic demand for refined products, and enhance the refinery's competitiveness and profitability.

In addition to the revamp of an existing residue fluidized catalytic cracker, SRIP involved installation of five new units at the refinery, including an 82,000-b/d crude distillation unit, vacuum distillation unit, delayed coker, hydrocracker, and bitumen-blowing unit.

Upon reaching full commercial operation, the newly expanded Sohar refinery will be equipped to process 198,000 b/d of crude into more than 13 million tpy of finished products, ORPIC said.

OxyChem, Mexichem launch Texas ethylene complex

Occidental Chemical Corp. (OxyChem) and Mexichem SAB de CV (Mexichem) have commissioned their 50-50 joint venture Ingleside Ethylene LLC's 1.2 billion-lb/year ethylene complex at Ingleside, Tex. (OGJ Online, Feb. 26, 2016).

Currently in a production stabilization phase, the OxyChem-operated ethane cracker reached startup on Feb. 27, the companies said.

Due to reach full production rates by the quarter's end, the cracker will process ethane feedstocks from US shale gas to supply OxyChem with an ongoing source of ethylene for manufacturing vinyl chloride monomer, which Mexichem will use to produce polyvinyl chloride (PVC) resin and PVC piping systems under an existing 20-year supply agreement.

Alongside the cracker, the $1.5-billion project also includes an associated pipeline and storage complex Markham, Tex. (OGJ Online, June 30, 2015).


Alberta pipeline report draws clarification

New pipeline-incident reporting by the Alberta government has evoked clarification from a company portrayed unfavorably in one of its operator comparisons.

When Alberta Energy Regulator introduced the report on Feb. 21, Pres. and Chief Executive Officer Jim Ellis said it would improve transparency and "drive increased industry accountability."

The report noted general improvement in pipeline safety, pointing out that incidents fell by 44% over the past 10 years as total pipeline length grew by 11%.

And it acknowledged that answering the question "Who are the poor performers?" isn't easy.

"The common standard for reporting on pipeline performance is as a ratio of incidents/1,000 km of pipeline," it said. "This provides an understanding of overall performance and is an important indicator, but it doesn't tell us the full story."

The top-ranked operator by that metric, Chinook Energy Inc. of Calgary, issued a statement clarifying what it called the "punitive and inaccurate rating" it received.

Chinook had one incident in 2016, a leak categorized by AER as "low consequence" during annual pressure-testing of a low-pressure pipeline in southern Alberta. At the time, Chinook had 1,300 km of pipeline under license and 880 km of operating pipeline in Alberta.

Since the leak, it has disposed of most of its producing properties in Alberta and now owns only 19.5 km of pipeline in the province. It was that total that AER used to calculate Chinook's top-ranked 52.44 incidents/1,000 km of pipeline.

"Had the AER's pipeline reporting analysis been calculated at the time of the incident," the company said in its statement, "Chinook would have scored an 0.8 incident factor per 1,000 km of total pipeline."

Still, the company commended the AER initiative and said it "is supportive of the improved pipeline performance mandate and the added public disclosure of safety and environmental incidents."

AER's pipeline report also ranked companies by total incidents, total high-consequence incidents, and total volume of product released.

The regulator plans similar reports covering in situ, mining

TransCanada offers Iroquois, PNGTS shares to MLP

TransCanada Corp. has offered to sell 49.3% interest in Iroquois Gas Transmission System LP, together with its remaining 11.8% interest in Portland Natural Gas Transmission System (PNGTS), to its master limited partnership, TC PipeLines LP.

The 416-mile Iroquois pipeline transports natural gas under long-term contracts from the TransCanada Mainline system at the US border near Waddington, NY, to the US Northeast, including New York City, Long Island, and Connecticut. Iroquois is jointly owned by affiliates of TransCanada and Dominion Resources Inc. through a joint venture.

PNGTS's 295 miles connect with the TransQuebec and Maritimes Pipeline at the Canadian border and share equipment with the Maritimes and Northeast Pipeline from Westbrook, Me., to a connection with the Tennessee Gas Pipeline System near Boston. PNGTS has a design capacity of 168 MMcfd at the Canadian border, increasing to 210 MMcfd from Westbrook to Dracut, Mass. In January 2016, TransCanada sold a 49.9% interest in PNGTS to TCP.